Fracturing treatments in subterranean formation using inorganic cements and electrically controlled propellants

ABSTRACT

Systems and methods for enhancing the conductivity of fractures in a subterranean formation using cements and electrically controlled propellant materials are provided. In some embodiments, the methods comprise: introducing a cement fluid comprising an aqueous base fluid, an inorganic cement, an electrically controlled propellant, and a plurality of electrically conductive particles into at least one fracture in a subterranean formation; allowing at least a portion of the cement fluid to at least partially harden in the fracture to form a solid cement mass; and applying an electrical current to at least a portion of the electrically controlled propellant in the fracture to ignite the electrically controlled propellant, whereby the solid cement mass in the fracture is at least partially ruptured by the ignition of the electrically controlled propellant.

CROSS-REFERENCE TO RELATED APPLICATION

The present application is a U.S. National Stage Application ofInternational Application No. PCT/US2017/014574 filed Jan. 23, 2017,which is incorporated herein by reference in its entirety for allpurposes.

BACKGROUND

The present disclosure relates to systems and methods for fracturing insubterranean formations.

Wells in hydrocarbon-bearing subterranean formations are oftenstimulated to produce those hydrocarbons using hydraulic fracturingtreatments. In hydraulic fracturing treatments, a viscous fracturingfluid, which also functions as a carrier fluid, is pumped into aproducing zone at a sufficiently high rate and/or pressure such that oneor more fractures are formed in the zone. These fractures provideconductive channels through which fluids in the formation such as oiland gas may flow to a well bore for production. In order to maintainsufficient conductivity through the fracture, it is often desirable thatthe formation surfaces within the fracture or “fracture faces” be ableto resist erosion and/or migration to prevent the fracture fromnarrowing or fully closing. Typically, proppant particulates suspendedin a portion of the fracturing fluid are also deposited in the fractureswhen the fracturing fluid is converted to a thin fluid to be returned tothe surface. These proppant particulates serve to prevent the fracturesfrom fully closing so that conductive channels are formed through whichproduced hydrocarbons can flow.

In many conventional fracturing treatments, large amounts of water orother fluids (e.g., an average of 1 million gallons per fracturingstage) are typically pumped at high rates and pressures in order toprovide sufficient energy downhole to form fractures in the formation ofthe desired geometries. Large amounts of proppant are also often used inthese operations; however, those proppants must be sized carefully toprevent premature screenout during their placement into the fracturesand efficiently prop open fractures in the well system, and the fluidscarrying those proppants must have sufficient viscosity to carry thoseproppants to their desired locations. Providing the large amounts ofpumping power, water, and proppants for these operations, and thedisposal of water flowing back out of the formation after thesetreatments, are often costly and time-consuming, and make fracturingoperations uneconomical in many circumstances.

BRIEF DESCRIPTION OF THE DRAWINGS

These drawings illustrate certain aspects of some of the embodiments ofthe present disclosure, and should not be used to limit or define theclaims.

FIG. 1 is a diagram illustrating an example of a fracturing system thatmay be used in accordance with certain embodiments of the presentdisclosure.

FIG. 2 is a diagram illustrating an example of a subterranean formationin which a fracturing operation may be performed in accordance withcertain embodiments of the present disclosure.

FIG. 3 is a diagram illustrating a portion of a subterranean formationduring a treatment in accordance with certain embodiments of the presentdisclosure.

FIG. 4 is a diagram illustrating the portion of a subterranean formationfrom FIG. 3 after the ignition of electrically controlled propellanttherein in accordance with certain embodiments of the presentdisclosure.

While embodiments of this disclosure have been depicted, suchembodiments do not imply a limitation on the disclosure, and no suchlimitation should be inferred. The subject matter disclosed is capableof considerable modification, alteration, and equivalents in form andfunction, as will occur to those skilled in the pertinent art and havingthe benefit of this disclosure. The depicted and described embodimentsof this disclosure are examples only, and not exhaustive of the scope ofthe disclosure.

DESCRIPTION OF CERTAIN EMBODIMENTS

The present disclosure relates to systems and methods for fracturingtreatments in subterranean formations. More particularly, the presentdisclosure relates to systems and methods for enhancing the conductivityof fractures in a subterranean formation using cements and electricallycontrolled propellant materials.

The present disclosure provides methods and systems using electricallycontrolled propellant to rupture hardened cement materials placed in theopen space of a fracture to form porous, conductive propped structuresin those fractures. In accordance with the methods of the presentdisclosure, a fracture is provided, created, or enhanced in at least aportion of a subterranean formation, typically by introducing afracturing fluid or pad fluid at a pressure sufficient to create thefracture. In certain methods of the present disclosure, the fracture maybe a preexisting fracture in the formation (e.g., a fracture formed in aprior hydraulic fracturing treatment), or may be newly generated duringa method of the present disclosure. A fluid comprising an aqueous basefluid, an inorganic cement, an electrically controlled propellant, and aplurality of electrically conductive particles is introduced into thefracture (or is introduced at sufficient pressure to create thefracture), and allowed to at least partially harden to form a solidand/or hardened cement mass having the electrically controlledpropellant embedded or dispersed therein. Once the solid cement mass hasbeen formed, an electrical current may be applied to at least a portionof the electrically controlled propellant in the solid cement mass toignite it. The combustion of the electrically controlled propellant mayrupture portions of the solid cement mass to form a porous, fluidicallyconductive cement mass in the fracture that has sufficient strength toprop open the fracture. The ignition of the propellant also may ruptureareas of the formation proximate to the fracture, forming additionalsecondary or tertiary fractures (e.g., cracks or fissures) therein.These secondary or tertiary fractures may enhance the connectivestimulated reservoir volume in the formation, which may stimulate theproduction of hydrocarbons therefrom and/or increase the fluidpermeability of those regions of the formation.

Among the many potential advantages to the methods and compositions ofthe present disclosure, only some of which are alluded to herein, themethods, compositions, and systems of the present disclosure may helpoptimize fracturing treatments in a number of ways. For example, in someembodiments, the methods of the present disclosure may minimize oreliminate the use of large volumes of fluids (e.g., water) and/orproppants used in conventional fracturing treatments, and/or reduce theamount of pumping horsepower required to create complex fracturinggeometries in subterranean formations. Reducing the amount of water usedin fracturing operations may, among other benefits, reduce flowbackvolume and/or costs of disposing flowback water. Reducing or eliminatingthe amount of fracturing sand or other proppants used in fracturingoperations may, among other benefits, simplify the composition offracturing fluids that no longer need to suspend proppant particulates,reduce proppant settling issues, and/or may decrease the abrasion towell site equipment from pumping proppant slurries into the formation.In certain embodiments, the ignition of the electrically controlledpropellants used in the methods and systems of the present disclosuremay be more effectively controlled as compared to other types ofexplosives or downhole energy sources. For example, these electricallycontrolled propellants may be less likely to spontaneously ignite,particularly at elevated pressure and/or temperature conditionsexperienced downhole. For these and other reasons, the methods andsystems of the present disclosure may present fewer or smaller safetyrisks in their transportation, handling, and use than other methods andsystems using other energy sources. Moreover, in some embodiments, itmay be possible to cease the ignition of an electrically controlledpropellant (e.g., by discontinuing the flow of electrical currenttherethrough), and then re-ignite the remaining portion of propellant ata subsequent time by re-applying electrical current to that same area.Consequently, in some embodiments, the methods and systems of thepresent disclosure may provide ways of fracturing or otherwisestimulating subterranean formations that can be used or actuatedrepeatedly without repeated interventions in the same well or placementof additional treatment fluids therein.

The inorganic cements used in the methods and compositions of thepresent disclosure may comprise any inorganic materials (or combinationthereof) that are capable of being hydrated in water to form a slurrythat can harden to form a solid mass. Such inorganic cements include,but are not limited to, hydraulic cements, geopolymer precursors, andthe like. Examples of hydraulic cements that may be suitable in certainembodiments of the present disclosure include, but are not limited to,Portland cement, pozzolanic cement, gypsum cement, high alumina contentcement, silica cement, high alkalinity cement, low-density cements,magnesium phosphate cement, and any combination thereof. Inorganicgeopolymers and/or geopolymer precursors used in certain embodiments ofthe present disclosure may comprise an aluminosilicate and an alkalinereagent. Examples of aluminosilicates that may be suitable in certainembodiments of the present disclosure include, but are not limited to,calcined clays, kaolinitic clays, lateritic clays, volcanic rocks, minetailings, blast furnace slag, coal fly ash, and any combination thereof.Examples of alkaline reagent that may be suitable in certain embodimentsof the present disclosure include, but are not limited to, sodiumsilicate solutions, potassium silicate solutions, and any combinationthereof. In some embodiments, the inorganic cement (or the fluidcomprising the inorganic cement) may further comprise additional cementadditives known in the art such as resins (e.g., a di- or poly epoxideresin), hardeners (e.g., an amine hardener), set retarders,strengthening materials (e.g., fibrous materials and/or di- orpolyfunctional alkylphosphonate ester fortifiers), and the like. Aperson of skill in the art with the benefit of this disclosure willrecognize when such additional additives may be beneficial in aparticular application of the present disclosure.

In some embodiments, the fluids comprising the inorganic cement may befoamed with a gas, which may harden to form cement masses of lowerdensities and/or higher porosities. In some embodiments, the fluidscomprising the inorganic cement optionally may be mixed with one or moredegradable materials that may be allowed to degrade after the cement hashardened in the fracture to further increase the porosity and/orconductivity of the hardened cement mass. Examples of degradablematerials that may be suitable in certain embodiments of the presentdisclosure include, but are not limited to, aliphatic polyesters,poly(lactides), poly(glycolides), poly(ε-caprolactones),poly(hydroxybutyrates), poly(anhydrides), aliphatic polycarbonate, orthoesters, poly(orthoesters), poly(vinylacetates), and any combinationthereof.

The electrically controlled propellants of the present disclosure maycomprise any substance known in the art that can be ignited by passingan electrical current through the propellant. The electricallycontrolled propellant may be provided as a liquid, or as a solid orsemi-solid (e.g., powders, pellets, etc.) dissolved, dispersed, orsuspended in a carrier liquid. In some embodiments, a liquid form may beparticularly suited to penetrating smaller cracks, microfractures,and/or bedding planes in a formation, among other reasons, to moreeffectively place the electrically controlled propellant in those areas.In some embodiments, electrically-controlled propellants provided insolid form may be used in lieu of or in combination with other proppantmaterials to prop open small cracks, fractures, or bedding planes in theformation (e.g., in the far well bore region of the formation) when thefracturing fluid pressure is released. Solid electrically controlledpropellants also may be more readily dispersed in a cement slurrycomprising the inorganic cement. In some embodiments, the electricallycontrolled propellant may be provided in a composition that comprises amixture of one or more electrically controlled propellants and othermaterials, including but not limited to inert materials such as sand,cement, fiberglass, ceramic materials, carbon fibers, polymericmaterials, sand, clay, acid soluble materials, degradable materials(e.g., polylactic acid), and the like. In certain embodiments, theelectrically controlled propellant may comprise a binder (e.g.,polyvinyl alcohol, polyvinylamine nitrate, polyethanolaminobutynenitrate, polyethyleneimine nitrate, copolymers thereof, and mixturesthereof), an oxidizer (e.g., ammonium nitrate, hydroxylamine nitrate,and mixtures thereof), and a crosslinking agent (e.g., boric acid). Suchpropellant compositions may further comprise additional optionaladditives, including but not limited to stability enhancing orcombustion modifying agents (e.g., 5-aminotetrazole or a metal complexthereof), dipyridyl complexing agents, polyethylene glycol polymers, andthe like. In certain embodiments, the electrically controlled propellantmay comprise a polyalkylammonium binder, an oxidizer, and an eutecticmaterial that maintains the oxidizer in a liquid form at the processtemperature (e.g., energetic materials such as ethanolamine nitrate(ETAN), ethylene diamine dinitrate (EDDN), or other alkylamines oralkoxylamine nitrates, or mixtures thereof). Such propellants mayfurther comprise a mobile phase comprising at least one ionic liquid(e.g., an organic liquid such as N,n-butylpyridinium nitrate). Certainof the aforementioned propellants may be commercially available fromDigital Solid State Propulsion, Inc. of Reno, Nev.

The electrically controlled propellants may be provided in the fluidcomprising the inorganic cement in any amount sufficient to provide thedesired amount of porosity and conductivity when the hardened cementmass is ruptured by their ignition that still allows for a hardenedcement mass of sufficient strength to withstand closure forces in thefracture. For example, if a more ruptured and more porous structure isdesired, the electrically controlled propellants may be included inhigher amounts/proportions relative to the amount of inorganic cement.In some embodiments, the electrically controlled propellant may beincluded in the fluid in an amount equal to the amount of the inorganiccement by weight (e.g., a 1:1 weight ratio). However, in otherembodiments, the fluid may comprise a smaller or larger amount of theelectrically controlled propellant as compared to the amount of theinorganic cement, so long as the cement will still have the desiredstrength once the electrically controlled propellant has been ignited.In some embodiments, the electrically controlled propellant may beincluded in the fluid in an amount of about half of the amount of theinorganic cement by weight (e.g., a 2:1 cement-to-propellant weightratio).

In certain embodiments, additional or secondary electrically controlledpropellants may be placed in areas of a subterranean formation proximateto the primary fracture, e.g., bedding planes or spaces between layersin a shale formation along the primary fracture or secondary fracturesin that area of the formation. These additional or secondaryelectrically controlled propellants may be ignited to create secondaryor tertiary fractures in the areas of the formation proximate to theprimary fracture, thereby creating a fracture network having a morecomplex and/or enhanced geometry. In certain of these embodiments, anon-cementitious fluid (e.g., a fluid that does not comprise asignificant amount of an inorganic cement, or alternatively, anyinorganic cement) that comprises the secondary electrically controlledpropellant (e.g., either in a solid or liquid form) may be introducedinto the formation before the fluid comprising the inorganic cement isintroduced. This non-cementitious fluid may be introduced so as to enteran existing fracture in the formation, or may be introduced at apressure sufficient to create one or more fractures, and then penetrateone or more areas proximate to that fracture. In certain embodiments,the ignition of the electrically controlled propellant may, in additionto the formation of secondary or tertiary fractures, rupture the nearbyrock formations to form rock particulates in the secondary or tertiaryfractures. In some embodiments, these rock particulates may act as anin-situ proppant material to prop open the secondary or tertiaryfractures and maintain their conductivity after the fracturing treatmentis completed.

In these embodiments, the additional or secondary electricallycontrolled propellants may be provided and/or placed in the subterraneanformation in any amount sufficient to provide the desired the amount ofenergy required to create or enlarge the desired connective stimulatedreservoir volumes in the formation when ignited. In some embodiments,the amount of energy needed to create or enlarge the desired fracturegeometries may be approximated as a function of the equivalent amount ofenergy created by pumping a fluid into the formation at a specificinjection rate and hydraulic horsepower that creates the bottomholetreating pressure required in conventional hydraulic fracturingtreatments. Using the heat of combustion of the electrically controlledpropellant, the amount of propellant needed to create that amount ofenergy may be calculated. The data from an example of these calculationsat various bottomhole treating pressures (BHTP) using ammonium nitrateas the propellant (heat of combustion=1,500 kJ/kg or 682 kJ/lb) is shownin Table 1.

TABLE 1 Equivalent Injection Pump Downhole Downhole Weight of BHTP Ratetime Energy Energy Ammonimum (psi) (bpm) (min) HHP (KW-hour) (kJ)Nitrate (lbs) 5,000 80 60 9,800 7,308 26,308,296 38,656 6,000 80 6011,760 8,769 31,569,955 46,387 7,000 80 60 13,720 10,231 36,831,61454,118 8,000 80 60 15,680 11,693 42,093,274 61,849 9,000 80 60 17,64013,154 47,354,933 69,580 10,000 80 60 19,600 14,616 52,616,592 77,31111,000 80 60 21,560 16,077 57,878,251 85,042 12,000 80 60 23,520 17,53963,139,910 92,774 13,000 80 60 25,480 19,000 68,401,570 100,505 14,00080 60 27,440 20,462 73,663,229 108,236 15,000 80 60 29,400 21,92478,924,888 115,967 10,000 15 60 3,675 2,740 9,865,611 14,496

As shown in the last row of Table 1, in some embodiments, a fracturingfluid may be able to create and hold open a fracture in a subterraneanformation when pumped at an injection rate of 15 barrels per minute(bpm) and a BHTP of 10,000 pounds per square inch (psi), requiring only3,675 HP of hydraulic horsepower to maintain the injection rate andinitiate and extend a primary fracture into the formation. In order tocreate more complex fracture geometries using conventional fracturingtreatments, the fracturing fluid would need to be injected at a higherrate or higher hydraulic horsepower. However, based on the calculateddata shown in Table 1, placing and igniting 77,311 lbs of an ammoniumnitrate-based electrically controlled propellant in the formation mayprovide an amount of energy equivalent to that provided in aconventional hydraulic fracturing treatment in which the fluid isinjected at a rate of 80 bpm and a BHTP of 10,000 psi for 60 minutes.

The treatment fluids used in the methods and systems of the presentdisclosure may comprise any base fluid known in the art, includingaqueous base fluids, non-aqueous base fluids, and any combinationsthereof. The term “base fluid” refers to the major component of thefluid (as opposed to components dissolved and/or suspended therein), anddoes not indicate any particular condition or property of that fluidssuch as its mass, amount, pH, etc. Aqueous fluids that may be suitablefor use in the methods and systems of the present disclosure maycomprise water from any source. Such aqueous fluids may comprise freshwater, salt water (e.g., water containing one or more salts dissolvedtherein), brine (e.g., saturated salt water), seawater, or anycombination thereof. In certain embodiments, the density of the aqueousfluid can be adjusted, among other purposes, to provide additionalparticulate transport and suspension in the compositions of the presentdisclosure. In certain embodiments, the pH of the aqueous fluid may beadjusted (e.g., by a buffer or other pH adjusting agent) to a specificlevel, which may depend on, among other factors, the types ofviscosifying agents, acids, and other additives included in the fluid.One of ordinary skill in the art, with the benefit of this disclosure,will recognize when such density and/or pH adjustments are appropriate.Moreover, in some embodiments, certain brine-based fluids may be exhibitcertain electrical conductivity properties, which may facilitateignition of the electrically controlled propellant once placed in thesubterranean formation. Examples of non-aqueous fluids (liquids orgases) that may be suitable for use in the methods and systems of thepresent disclosure include, but are not limited to, oils, hydrocarbons(e.g., liquefied natural gas (LNG), methane, etc.), organic liquids,carbon dioxide, nitrogen, and the like. In certain embodiments, thecementing fluids, fracturing fluids, and other treatment fluidsdescribed herein may comprise a mixture of one or more fluids and/orgases, including but not limited to emulsions, foams, and the like.

In some embodiments, certain fracturing fluids or other treatment fluidsused in the methods of the present disclosure may be substantially“waterless” in that they do not comprise a significant amount of water(e.g., less than 5%, 1%, or 0.1% by volume), or alternatively, anyamount of water. In some embodiments, certain fracturing fluids or othertreatment fluids (e.g., fluids used to place additional or secondaryelectrically controlled propellant, such as a liquid electricallycontrolled propellant, into bedding planes or other areas of theformation adjacent to the primary fracture) may be substantially“solids-free” in that they do not comprise a significant amount of solidmaterial (e.g., less than 5%, 1%, or 0.1% by weight), or alternatively,any amount of solid material.

In some embodiments, the viscosity of the treatment fluid(s) used duringdifferent portions of the methods of the present disclosure optionallymay be varied, among other reasons, to provide different amounts offluid loss control and/or leakoff that may be useful during thosedifferent steps. For example, in some embodiments, the fracturing fluidor pad fluid introduced at or above a pressure sufficient to create orenhance a primary fracture may be relatively viscous (e.g., about 250 cPor higher, up to about 5,000 cP), among other reasons, to minimize fluidleakoff and maintain a high bottomhole treating pressure in theformation. In some embodiments, fluids comprising an additional orsecondary electrically controlled propellant (either a fluid differentfrom the fracturing fluid or a different stage of the same fracturingfluid) may have a relatively low viscosity (e.g., about 50 cP or lower,or 5 cP or lower), among other reasons, to facilitate leakoff andpenetration of the propellant into bedding planes, microfractures, orother areas of the formation proximate to the primary fracture. In someembodiments, the fluid comprising the inorganic cement and electricallycontrolled propellant may be followed by another relatively viscousfluid introduced into the formation, among other reasons, to displacethe fluid comprising the propellant and cement into the far well boreregion of the formation with less loss or leakoff of that fluid. Thehigher viscosity of this fluid also may facilitate suspension ofelectrically conductive particulates and/or proppant particulates to bedeposited in the near well bore portion of the primary fracture. Anycompatible, known viscosifying agents as well as any compatible, knowncrosslinking agents (e.g., metal carboxylate crosslinkers) capable ofcrosslinking the molecules of a polymeric viscosifying agent may be usedin accordance with the methods of the present disclosure.

In certain embodiments, the treatment fluids used in the methods andsystems of the present disclosure optionally may comprise any number ofadditional additives. Examples of such additional additives include, butare not limited to, salts, surfactants, acids, proppant particulates(e.g., frac sand), diverting agents, fluid loss control additives, gas,nitrogen, carbon dioxide, surface modifying agents, tackifying agents,foamers, corrosion inhibitors, scale inhibitors, catalysts, clay controlagents, biocides, friction reducers, antifoam agents, bridging agents,flocculants, H₂S scavengers, CO₂ scavengers, oxygen scavengers,lubricants, viscosifiers, crosslinking agents, breakers, weightingagents, relative permeability modifiers, resins, wetting agents, coatingenhancement agents, filter cake removal agents, antifreeze agents (e.g.,ethylene glycol), and the like. In certain embodiments, one or more ofthese additional additives (e.g., a crosslinking agent) may be added tothe treatment fluid and/or activated after the viscosifying agent hasbeen at least partially hydrated in the fluid. A person skilled in theart, with the benefit of this disclosure, will recognize the types ofadditives that may be included in the fluids of the present disclosurefor a particular application.

In some embodiments, a treatment fluid comprising a consolidating agentsuch as a curable resin optionally may be introduced into thesubterranean formation after the electrically controlled propellant isignited, among other reasons, to consolidate loose particulates, treatnewly-created fracture faces and/or strengthen the ruptured cement massand/or other areas of the formation that have been ruptured or fracturedby the combustion of the propellant. In some embodiments, theconsolidating agent may be introduced into a primary fracture and/orallowed to penetrate any secondary and/or tertiary fractures created bythe combustion of the electrically controlled propellant. Theconsolidating agent may, among other benefits, treat the fracture facesin the primary, secondary, or tertiary fractures in the formation, andlock in place any formation fines and/or loose rock particulates (e.g.,rock particulates generated when the electrically controlled propellantwas ignited). Any consolidating agent known in the art, includingresins, tackifiers, and the like, may be used in accordance with themethods of the present disclosure. In some embodiments, preflush and/orafterflush fluids may be introduced into the formation before and/orafter the consolidating agent is introduced, among other reasons, toprepare the rock surfaces for treatment and/or to displace excessconsolidating agent from pore spaces in the formation and/or rupturedcement mass.

The treatment fluids of the present disclosure may be prepared using anysuitable method and/or equipment (e.g., blenders, mixers, stirrers,etc.) known in the art at any time prior to their use. The treatmentfluids may be prepared at least in part at a well site or at an offsitelocation. In certain embodiments, the electrically controlled propellantand/or other components of the treatment fluid may be metered directlyinto a base treatment fluid to form a treatment fluid. In certainembodiments, the base fluid may be mixed with the electricallycontrolled propellant, inorganic cement, and/or other components of thetreatment fluid at a well site where the operation or treatment isconducted, either by batch mixing or continuous (“on-the-fly”) mixing.The term “on-the-fly” is used herein to include methods of combining twoor more components wherein a flowing stream of one element iscontinuously introduced into a flowing stream of another component sothat the streams are combined and mixed while continuing to flow as asingle stream as part of the on-going treatment. Such mixing can also bedescribed as “real-time” mixing. In other embodiments, the treatmentfluids of the present disclosure may be prepared, either in whole or inpart, at an offsite location and transported to the site where thetreatment or operation is conducted. In introducing a treatment fluid ofthe present disclosure into a portion of a subterranean formation, thecomponents of the treatment fluid may be mixed together at the surfaceand introduced into the formation together, or one or more componentsmay be introduced into the formation at the surface separately fromother components such that the components mix or intermingle in aportion of the formation to form a treatment fluid. In either such case,the treatment fluid is deemed to be introduced into at least a portionof the subterranean formation for purposes of the present disclosure.

As noted above, an electrical current must be applied to theelectrically controlled propellant to ignite it in the methods of thepresent disclosure. That electrical current may be transmitted orotherwise provided to the electrically controlled propellant in theformation using any means known in the art. In some embodiments,electrical current is provided from a direct current (DC) source,although electrical power from alternating current (AC) sources can beused as well. In some embodiments, the source of electrical current maybe provided at the surface, and the current may be transferred via aconductive wire, cable, and/or tubing into the subterranean formation tothe electrically controlled propellant and/or another electricallyconductive material in contact with the propellant. In theseembodiments, the electrical current may pass through any number ofsecondary relays, switches, conduits (e.g., wires or cables),electrodes, equipment made of conductive material (e.g., metal casings,liners, etc.) or other electrically conductive structures. In otherembodiments, the electrical current also may be provided by some otherdownhole energy source (such as downhole charges, hydraulic powergenerators, batteries, or the like), and then applied to theelectrically controlled propellant in the formation. In certainembodiments, the amount of electrical current applied to ignite theelectrically controlled propellant may range from about 1 milliamp toabout 100 milliamps. In certain embodiments, the electrical currentapplied to ignite the electrically controlled propellant may have acorresponding voltage of from about 100V to about 600V.

The electrically controlled propellant may be ignited at any time, andthe application of electrical current to the propellant may be triggeredin any known way. In some embodiments, the current may be applied inresponse to manual input by an operator, either at the surface of thewell site or from a remote location. In other embodiments, the currentmay be applied automatically in response to the detection of certainconditions in the formation using one or more downhole sensors. Examplesof downhole sensors that may be used in this way include, but are notlimited to, pressure sensors, temperature sensors, water sensors, motionsensors, chemical sensors, and the like.

As discussed above, particles of electrically conductive materialsoptionally may be placed in various regions of the formation, amongother reasons, to help transmit electrical current to facilitateignition and removal of the electrically controlled propellant when thecurrent is applied, even in far-field regions of a subterraneanformation. For example, in some embodiments, electrically conductiveparticles may be mixed in the same fluid with the electricallycontrolled propellants and/or cement, among other reason, to facilitateplacement of those particles proximate to and/or in contact with thepropellants. In certain embodiments, the electrically conductivematerials may comprise micro- and/or nano-sized particles. Examples ofelectrically conductive materials that may be suitable in certainembodiments of the present disclosure include but are not limited tometal powders, metal shavings, steel shot, graphite, calcined coke,metal coated particles, particles coated with electrically conductivepolymer, and any combinations thereof. Examples of conductive metalsthat may be suitable for use in certain embodiments of the presentdisclosure include, but are not limited to, graphite, silver, gold,calcium lithium, platinum, titanium, nickel, copper, iron, silver, zinc,brass, tin, aluminum, steel, lead, magnesium, and any alloy orcombination thereof. In some embodiments, the electrically conductivematerial may comprise an electrically conductive polymer material, suchas at least one of a polypyrrole, polyfuran, polythiophene, polyaniline,as well as any copolymers, combinations, and/or derivatives thereof.

In some embodiments, the electrical current may be applied to theelectrically controlled propellant substantially continuously untilsubstantially all of the propellant has been ignited or the desiredfracture geometries have been created in the formation. In otherembodiments, the electrical current may be applied to the electricallycontrolled propellant intermittently. The intermittent ignition of thepropellant may generate a series of shorter pulses of energy and/orpressure in the primary fracture and/or the area of the formationproximate to the primary fracture. The cracks and fractures in thehardened cement mass and/or the formation may be permitted to relax orconstrict between these intermittent pulses, which may facilitate thecreation of more complex fracture geometries and/or more conductiveruptured cement masses.

An example of a fracture network created and/or enhanced according tothe methods of the present disclosure is illustrated in FIGS. 3 and 4.Referring now to FIG. 3, a well bore 313 is shown penetrating a portionof a subterranean formation 310. Relative to the location of the wellbore 313, the subterranean formation 310 may comprise a near well boreregion 310 a and a far well bore region 310 b. The distances from thewell bore 313 at which these regions are delineated are not shown toscale in FIGS. 3 and 4, and may vary depending on the application of thepresent disclosure, but would be recognized by a person of skill in theart with the benefit of this disclosure. In some embodiments, the regionwithin about 10 meters (about 33 feet) of the well bore may beconsidered the near well bore region 310 a, and the region more thanabout 10 meters beyond the well bore may be considered the far well boreregion 310 b. A casing string 317 is disposed within the well bore 313and is held in place by cement 315 placed in an annular area between thewell bore 313 and the outer surface of the casing 317. In order to allowfluid flow between the formation 310 and the inside of the casing 317and well bore 313, perforations 319 may be created through the casing313 and cement 317 in selected locations. The portion of the well bore313 shown in FIGS. 3 and 4 is oriented horizontally, although a personof skill in the art with the benefit of this disclosure will recognizethat the methods of the present disclosure could be similarly applied tosections of a well bore that are vertical or deviated from vertical to alesser degree. Also, the methods of the present disclosure may beapplied to open holes which may lack casing strings, cement, and orperforations shown in FIGS. 3 and 4.

A primary fracture 325 extends from the well bore 313 to penetrate boththe near well bore region 310 a and the far well bore region 310 b ofthe subterranean formation 310. The primary fracture 325 may have beencreated by introducing a fracturing fluid (e.g., a fracturing fluid ofthe present disclosure, or a conventional fracturing fluid) into thesubterranean formation at or above a pressure sufficient to create orenlarge the fracture 325. In some embodiments, the portion of the wellbore 313 adjacent to the fracture 325 may have been isolated (e.g.,using packers, plugs, or other isolation tools) before the fracturingfluid was introduced. A hardened cement mass 328 resides within the farwell bore portion of the primary fracture 325 after a fluid comprisingthe inorganic cement has been allowed to harden. In some embodiments,the well bore 313 may be shut in for a certain period of time (which maybe as short as one hour or as long as several days) to allow the cementto harden in the fracture 325. In other embodiments, e.g., in hightemperature formations, the cement may harden more quickly and a shut-inperiod may not be necessary for the cement to harden. Embedded ordispersed within the hardened cement mass 328 are solid particles ofelectrically controlled propellant 330.

As shown, the primary fracture 325 also penetrates a number of beddingplanes 335 of the formation 310. Electrically controlled propellant 340has been placed in the bedding planes 335 in at least the far well boreregion 310 b via the primary fracture 325, before the cement wasintroduced into the primary fracture 325. In some embodiments,electrically controlled propellant may not be placed in bedding planesin the near well bore region 310 a, among other reasons, to preventdamage to that region and/or the well bore. A plurality of proppantparticulates 345 also have been placed in the near well bore portion ofthe primary fracture 325, among other reasons, to maintain theconductivity of the primary fracture and to protect the well bore. Thesame fluid used to place proppant particulates 345 also may have beenused to displace the fluid comprising the inorganic cement and theelectrically controlled propellant into the far well bore region 310 bof the fracture 325. Thus, FIG. 3 shows the portion of the formation 310prior to ignition of the electrically controlled propellant according tothe methods of the present disclosure.

Referring now to FIG. 4, the same formation 310 as shown in FIG. 3 isshown after ignition of at least a portion of the electricallycontrolled propellant in the primary fracture 325 and in the beddingplanes 335. The ignition of the propellant 330 from FIG. 3 has rupturedthe hardened cement mass 328 from FIG. 3 to form a porous cementstructure 332 residing within the far well bore region of the primaryfracture 325. The structure 332 is sufficiently porous such that fluidsmay flow through it either into or out of the fracture 325, but is alsostrong enough to withstand closure forces in the fracture 325. Theignition of the propellant also has ruptured the formation rock in thefar well bore region 310 b to form secondary fractures 355 therein. Asshown, the near well bore region 310 a remains substantially undisruptedbecause electrically controlled propellant was not placed or ignited inbedding planes in the near well bore region 310 a of the formation orthe near well bore portion of fracture 325. The combination of thesecondary fractures 355, bedding planes 335, and primary fracture 325form a conductive fracture network 360 through which fluids such as oil,gas, and/or water may flow from the formation 310 into the well bore 313for production.

Although not shown, the aforementioned features of the portion of thesubterranean formation 310 and fracture network 350 shown above the wellbore 313 also may exist and/or be created below the well bore 313 (e.g.,as in a “bi-wing” fracture configuration, similar to that illustrated asfracture 116 in FIG. 2) in the methods of the present disclosure.

Certain embodiments of the methods and compositions disclosed herein maydirectly or indirectly affect one or more components or pieces ofequipment associated with the preparation, delivery, recapture,recycling, reuse, and/or disposal of the disclosed compositions. Forexample, and with reference to FIG. 1, the disclosed methods andcompositions may directly or indirectly affect one or more components orpieces of equipment associated with an exemplary fracturing system 10,according to one or more embodiments. In certain instances, the system10 includes a fracturing fluid producing apparatus 20, a fluid source30, a proppant source 40, and a pump and blender system 50 and residesat the surface at a well site where a well 60 is located. In certaininstances, the fracturing fluid producing apparatus 20 combines a gelpre-cursor with fluid (e.g., liquid or substantially liquid) from fluidsource 30, to produce a hydrated fracturing fluid that is used tofracture the formation. The hydrated fracturing fluid can be a fluid forready use in a fracture stimulation treatment of the well 60 or aconcentrate to which additional fluid is added prior to use in afracture stimulation of the well 60. In other instances, the fracturingfluid producing apparatus 20 can be omitted and the fracturing fluidsourced directly from the fluid source 30. In certain instances, thefracturing fluid may comprise water, a hydrocarbon fluid, a polymer gel,foam, air, wet gases and/or other fluids.

The proppant source 40 can include a proppant for combination with thefracturing fluid. The system may also include additive source 70 thatmay provide electrically controlled propellant and/or one or moreadditives (e.g., gelling agents, weighting agents, and/or other optionaladditives) to alter the properties of the fracturing fluid. For example,the other additives 70 can be included to reduce pumping friction, toreduce or eliminate the fluid's reaction to the geological formation inwhich the well is formed, to operate as surfactants, and/or to serveother functions.

The pump and blender system 50 receives the fracturing fluid andcombines it with other components, including proppant from the proppantsource 40 and/or additional fluid from the additives 70. The resultingmixture may be pumped down the well 60 under a pressure sufficient tocreate or enhance one or more fractures in a subterranean zone, forexample, to stimulate production of fluids from the zone. Notably, incertain instances, the fracturing fluid producing apparatus 20, fluidsource 30, and/or proppant source 40 may be equipped with one or moremetering devices (not shown) to control the flow of fluids, proppants,and/or other compositions to the pumping and blender system 50. Suchmetering devices may permit the pumping and blender system 50 can sourcefrom one, some or all of the different sources at a given time, and mayfacilitate the preparation of fracturing fluids in accordance with thepresent disclosure using continuous mixing or “on-the-fly” methods.Thus, for example, the pumping and blender system 50 can provide justfracturing fluid into the well at some times, just proppants at othertimes, and combinations of those components at yet other times.

FIG. 2 shows the well 60 during a fracturing operation in a portion of asubterranean formation of interest 102 surrounding a well bore 104. Thewell bore 104 extends from the surface 106, and the fracturing fluid 108is applied to a portion of the subterranean formation 102 surroundingthe horizontal portion of the well bore. Although shown as verticaldeviating to horizontal, the well bore 104 may include horizontal,vertical, slant, curved, and other types of well bore geometries andorientations, and the fracturing treatment may be applied to asubterranean zone surrounding any portion of the well bore. The wellbore 104 can include a casing 110 that is cemented or otherwise securedto the well bore wall. The well bore 104 can be uncased or includeuncased sections. Perforations can be formed in the casing 110 to allowfracturing fluids and/or other materials to flow into the subterraneanformation 102. In cased wells, perforations can be formed using shapecharges, a perforating gun, hydro jetting and/or other tools. Theportion of the well bore 104 proximate to the portion of thesubterranean formation 102 to be fractured also may be isolated usingany known method of zonal isolation, including but not limited topackers, plugs, gels, valves, and the like.

The well is shown with a work string 112 depending from the surface 106into the well bore 104. The pump and blender system 50 is coupled a workstring 112 to pump the fracturing fluid 108 into the well bore 104. Theworking string 112 may include coiled tubing, jointed pipe, and/or otherstructures that allow fluid to flow into the well bore 104. The workingstring 112 can include flow control devices, bypass valves, ports, andor other tools or well devices that control a flow of fluid from theinterior of the working string 112 into the subterranean zone 102. Forexample, the working string 112 may include ports adjacent the well borewall to communicate the fracturing fluid 108 directly into thesubterranean formation 102, and/or the working string 112 may includeports that are spaced apart from the well bore wall to communicate thefracturing fluid 108 into an annulus in the well bore between theworking string 112 and the well bore wall.

The working string 112 and/or the well bore 104 may include one or moresets of packers 114 that seal the annulus between the working string 112and well bore 104 to define an interval of the well bore 104 into whichthe fracturing fluid 108 will be pumped. FIG. 2 shows two packers 114,one defining an uphole boundary of the interval and one defining thedownhole end of the interval. When the fracturing fluid 108 isintroduced into well bore 104 (e.g., in FIG. 2, the area of the wellbore 104 between packers 114) at a sufficient hydraulic pressure, one ormore fractures 116 may be created in the subterranean zone 102.

While not specifically illustrated herein, the disclosed methods andcompositions may also directly or indirectly affect any transport ordelivery equipment used to convey the compositions to the fracturingsystem 10 such as, for example, any transport vessels, conduits,pipelines, trucks, tubulars, and/or pipes used to fluidically move thecompositions from one location to another, any pumps, compressors, ormotors used to drive the compositions into motion, any valves or relatedjoints used to regulate the pressure or flow rate of the compositions,and any sensors (i.e., pressure and temperature), gauges, and/orcombinations thereof, and the like.

An embodiment of the present disclosure is a method comprising:introducing a fracturing fluid comprising an aqueous base fluid, aninorganic cement, an electrically controlled propellant, and a pluralityof electrically conductive particles into at least a portion of asubterranean formation at or above a pressure sufficient to create orenhance at least one fracture in the subterranean formation; allowing atleast a portion of the fracturing fluid to at least partially harden inthe fracture to form a solid cement mass; and applying an electricalcurrent to at least a portion of the electrically controlled propellantin the fracture to ignite the electrically controlled propellant,whereby the solid cement mass in the fracture is at least partiallyruptured by the ignition of the electrically controlled propellant.

Another embodiment of the present disclosure is a method comprising:introducing a cement fluid comprising an aqueous base fluid, aninorganic cement, an electrically controlled propellant, and a pluralityof electrically conductive particles into at least one fracture in asubterranean formation; allowing at least a portion of the cement fluidto at least partially harden in the fracture to form a solid cementmass; and applying an electrical current to at least a portion of theelectrically controlled propellant in the fracture to ignite theelectrically controlled propellant, whereby the solid cement mass in thefracture is at least partially ruptured by the ignition of theelectrically controlled propellant.

Another embodiment of the present disclosure is a fracture network in asubterranean formation comprising: a well bore penetrating at least aportion of the subterranean formation; a primary fracture in thesubterranean formation in fluid communication with the well bore,wherein a plurality of proppant particulates and a first plurality ofelectrically conductive particles are located within a portion of theprimary fracture in a near well bore area of the subterranean formation,and a solid fluidically conductive cement mass and a second plurality ofelectrically conductive particles are located within a portion of theprimary fracture in a far well bore area of the subterranean formation;and one or more secondary or tertiary fractures in the subterraneanformation in fluid communication with the primary fracture formed atleast in part by ignition of a liquid electrically controlled propellantin a far well bore area of the subterranean formation proximate to theprimary fracture.

Another embodiment of the present disclosure is a fractured portion of asubterranean formation comprising: a well bore penetrating at least theportion of the subterranean formation; a primary fracture in the portionof the subterranean formation in fluid communication with the well bore,wherein a plurality of proppant particulates and a first plurality ofelectrically conductive particles are located within a portion of theprimary fracture in a near well bore area of the subterranean formation,and a solid cement mass, an electrically controlled propellant, and asecond plurality of electrically conductive particles are located withina portion of the primary fracture in a far well bore area of thesubterranean formation; and a liquid electrically controlled propellantin a far well bore area of the subterranean formation proximate to theprimary fracture.

Therefore, the present disclosure is well adapted to attain the ends andadvantages mentioned as well as those that are inherent therein. Theparticular embodiments disclosed above are illustrative only, as thepresent disclosure may be modified and practiced in different butequivalent manners apparent to those skilled in the art having thebenefit of the teachings herein. While numerous changes may be made bythose skilled in the art, such changes are encompassed within the spiritof the subject matter defined by the appended claims. Furthermore, nolimitations are intended to the details of construction or design hereinshown, other than as described in the claims below. It is thereforeevident that the particular illustrative embodiments disclosed above maybe altered or modified and all such variations are considered within thescope and spirit of the present disclosure. In particular, every rangeof values (e.g., “from about a to about b,” or, equivalently, “fromapproximately a to b,” or, equivalently, “from approximately a-b”)disclosed herein is to be understood as referring to the power set (theset of all subsets) of the respective range of values. The terms in theclaims have their plain, ordinary meaning unless otherwise explicitlyand clearly defined by the patentee.

What is claimed is:
 1. A method comprising: introducing a fracturingfluid comprising an aqueous base fluid, an inorganic cement, anelectrically controlled propellant, and a plurality of electricallyconductive particles into at least a portion of a subterranean formationat or above a pressure sufficient to create or enhance at least onefracture in the subterranean formation, wherein the electricallycontrolled propellant comprises: a binder selected from the groupconsisting of: polyvinyl alcohol, polyvinylamine nitrate,polyethanolaminobutyne nitrate, polyethyleneimine nitrate, any copolymerthereof, and any mixture thereof; an oxidizer selected from the groupconsisting of: ammonium nitrate, hydroxylamine nitrate, and any mixturethereof; and a crosslinking agent wherein the electrically controlledpropellant is present in the fracturing fluid in an amount of betweenabout a 1:1 and a 2:1 cement-to-propellant weight ratio; allowing atleast a portion of the fracturing fluid to at least partially harden inthe fracture to form a solid cement mass; and applying an electricalcurrent to at least a portion of the electrically controlled propellantin the fracture to ignite the electrically controlled propellant,whereby the solid cement mass in the fracture is at least partiallyruptured by the ignition of the electrically controlled propellant. 2.The method of claim 1 wherein igniting the electrically controlledpropellant further causes the formation of one or more secondary ortertiary fractures in the subterranean formation in an area proximate tothe fracture.
 3. The method of claim 1 wherein the electricallycontrolled propellant comprises a solid electrically controlledpropellant.
 4. The method of claim 1 wherein the electrical current isapplied in an amount of from about 1 milliamp to about 100 milliamps. 5.The method of claim 1 wherein applying the electrical current to atleast a portion of the electrically controlled propellant comprisesapplying the electrical current to at least a portion of a casing in awell bore penetrating at least the first portion of the subterraneanformation.
 6. The method of claim 1 wherein applying the electricalcurrent to the portion of the electrically controlled propellantcomprises applying the electrical current to the portion of theelectrically controlled propellant intermittently.
 7. The method ofclaim 1 wherein the fracturing fluid further comprises one or moredegradable materials.
 8. The method of claim 1 wherein allowing at leasta portion of the fracturing fluid to at least partially harden comprisesshutting a well bore penetrating the subterranean formation.
 9. Themethod of claim 1 further comprising introducing a plurality of proppantparticulates and a second plurality of electrically conductive particlesinto a portion of the primary fracture in a near well bore area of thesubterranean formation after the step of introducing the fracturingfluid into the subterranean formation and before the step of applyingthe electrical current to the electrically controlled propellant. 10.The method of claim 1 further comprising displacing the fracturing fluidinto a far well bore area of the subterranean formation.
 11. A methodcomprising: introducing a cement fluid comprising an aqueous base fluid,an inorganic cement, an electrically controlled propellant, and aplurality of electrically conductive particles into at least onefracture in a subterranean formation, wherein the electricallycontrolled propellant comprises: a binder selected from the groupconsisting of: polyvinyl alcohol, polyvinylamine nitrate,polyethanolaminobutyne nitrate, polyethyleneimine nitrate, any copolymerthereof, and any mixture thereof; an oxidizer selected from the groupconsisting of: ammonium nitrate, hydroxylamine nitrate, and any mixturethereof; and a crosslinking agent wherein the electrically controlledpropellant is present in the cement fluid in an amount of between abouta 1:1 and a 2:1 cement-to-propellant weight ratio; allowing at least aportion of the cement fluid to at least partially harden in the fractureto form a solid cement mass; and applying an electrical current to atleast a portion of the electrically controlled propellant in thefracture to ignite the electrically controlled propellant, whereby thesolid cement mass in the fracture is at least partially ruptured by theignition of the electrically controlled propellant.
 12. The method ofclaim 11 further comprising introducing a fracturing fluid at or above apressure sufficient to create or enhance the at least one fracture inthe subterranean formation before the step of introducing the cementfluid into the at least one fracture.
 13. The method of claim 12 whereinthe fracturing fluid comprises less than 5% solids by weight.
 14. Themethod of claim 12 wherein the fracturing fluid comprises less than 5%water by volume.
 15. The method of claim 12 wherein the fracturing fluidcomprises a secondary electrically controlled propellant.
 16. The methodof claim 11 further comprising: introducing a non-cementitious fluidcomprising a secondary liquid electrically controlled propellant intothe fracture to place the secondary electrically controlled propellantin one or more areas of the subterranean formation proximate to thefracture before introducing the cement fluid into the fracture; andapplying an electrical current to at least a portion of the secondaryelectrically controlled propellant to ignite the portion of thesecondary electrically controlled propellant in the one or more areas ofthe subterranean formation proximate to the fracture to form one or moresecondary or tertiary fractures in the subterranean formation.
 17. Themethod of claim 16 wherein the non-cementitious fluid further comprisesa secondary plurality of electrically conductive particles that areplaced in the fracture.
 18. A fracture network in a subterraneanformation comprising: a well bore penetrating at least a portion of thesubterranean formation; a primary fracture in the subterranean formationin fluid communication with the well bore, wherein a plurality ofproppant particulates and a first plurality of electrically conductiveparticles are located within a portion of the primary fracture in a nearwell bore area of the subterranean formation, and a solid fluidicallyconductive cement mass and a second plurality of electrically conductiveparticles are located within a portion of the primary fracture in a farwell bore area of the subterranean formation; and one or more secondaryor tertiary fractures in the subterranean formation in fluidcommunication with the primary fracture formed at least in part byignition of a liquid electrically controlled propellant in a far wellbore area of the subterranean formation proximate to the primaryfracture, wherein the liquid electrically controlled propellant isprovided to the primary fracture in a fluid comprising an aqueous basefluid, an inorganic cement, an electrically controlled propellant, and aplurality of electrically conductive particles, wherein the electricallycontrolled propellant comprises: a binder selected from the groupconsisting of: polyvinyl alcohol, polyvinylamine nitrate,polyethanolaminobutyne nitrate, polyethyleneimine nitrate, any copolymerthereof, and any mixture thereof; an oxidizer selected from the groupconsisting of: ammonium nitrate, hydroxylamine nitrate, and any mixturethereof; and a crosslinking agent, wherein the electrically controlledpropellant is included in the fluid in an amount of between about a 1:1and a 2:1 cement-to-propellant weight ratio.
 19. The fracture network ofclaim 18 wherein the solid fluidically conductive cement mass has beenat least partially ruptured by ignition of a primary electricallycontrolled propellant placed in the far well bore area of the primaryfracture.